Defoaming Systems and Methods in Hydrocarbon Processes

ABSTRACT

Methods for defoaming in hydrocarbon processes include the steps of providing a defoaming agent, and introducing the agent into a hydrocarbon process to inhibit or control foaming in the hydrocarbon process. These methods may be particularly useful in coking processes, especially as to foaming in coke drums. In certain embodiments, defoaming agents may comprise a plurality of carbon nanoparticles. In some embodiments, drag reducing agents may comprise high-molecular weight alkanes. Advantages include, but are not limited to, more efficient and effective foam inhibition, reduced or eliminated product contamination, reduced or eliminated catalyst poisoning, increased refinery production rate, debottlenecking the coker, and reduced cost and consequences of applying too much antifoam.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.14/370,463 filed on Jul. 2, 2014 which claims the priority of PCT PatentApplication Serial No. PCT/US12/24461, filed on Feb. 9, 2012, and whichare incorporated herein by reference.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH

Not applicable.

FIELD OF THE INVENTION

The present invention generally relates to systems and methods fordefoaming in hydrocarbon processes. More particularly, the presentinvention related to inhibiting or controlling foaming in hydrocarbonprocesses.

BACKGROUND OF THE INVENTION

Foaming in hydrocarbon processes is usually undesirable as foamingtypically adversely affects hydrocarbon process efficiencies. Oneexample of a hydrocarbon process that can be acutely affected byundesirable foaming is coking.

Coking is one of the older refining processes. The purpose of a cokeplant is to convert heavy residual oils (e.g. tar, asphalt, etc.) intolighter, more valuable motor fuel blending stocks. Refinery coking iscontrolled, severe, thermal cracking. It is a process in which the highmolecular weight hydrocarbon residue (normally from the bottoms of thevacuum flasher in a refinery crude unit) are cracked or broken up intosmaller and more valuable hydrocarbons.

Coking is accomplished by subjecting the feed charge to an extremetemperature of approximately 950° F. that initiates the crackingprocess. The light hydrocarbons formed as a result of the crackingprocess flash off and are separated in conventional fractionatingequipment. The material that is left behind after cracking is coke,which is almost pure carbon. In addition to coke, which is of value inthe metal industry in the manufacture of electrodes, fuel coke, titaniumdioxide, etc., the products of a coke plant include gas (refinery fueland LPG), unstabilized (wild) gasoline, light gas oil, and heavy gasoil.

The lion's share of the world's coking capacity is represented bydelayed coking processes. Delayed coking can be thought of as acontinuous batch reaction. The process makes use of paired coke drums.One drum (the active drum) is used as a reaction vessel for the thermalcracking of residual oils. This active drum slowly fills with coke asthe cracking process proceeds. While the active drum is being filledwith coke, a second drum (the inactive drum) is in the process of havingcoke removed from it. The coke drums are sized so that by the time theactive drum is filled with coke, the inactive drum is empty. The processflow is then switched to the empty drum, which becomes the active drum.The full drum becomes the inactive drum and is emptied or decoked. Byswitching the process flow back and forth between the two drums in thisway, the coking operation can continue uninterrupted.

After being heated in a direct-fired furnace, the oil is charged to thebottom of the active coke drum. The cracked light hydrocarbons rise tothe top of the drum where they are removed and charged to a fractionatorfor separation. The heavier hydrocarbons are left behind, and theretained heat causes them to crack to coke.

One problem frequently encountered in coke production is foaming in thecoke drums. In coking processes, foam formation is the result of evolvedgas molecules in a liquid. Foaming is a function of many variablesincluding surface tension, pressure, viscosity, and other properties ofthe gas/liquid system. While foaming in aqueous systems has been studiedextensively, relatively little is known about controlling foaming inorganic systems. This foaming problem is particularly acute in the laterportions of a fill cycle or when a coke drum is depressured beforecoking is completed. Foaming is especially problematic because of thepossibility of carry-over which can result in plugged overhead lines andlost profit opportunity to clean the lines. Foaming in coke drums alsoreduces the useable space in the drums for coke capacity, ultimatelylimiting total production capacity.

Conventional approaches for addressing foaming in coke drums suffer froma variety of significant disadvantages. One approach for dealing withfoaming is to simply decrease production rates to limit foaming. Thisapproach is obviously disadvantageous in that overall production isreduced. The temperature can also be increased, but this shortens therun length of the coker furnace because the fouling rate increases inthe furnace tubes, unfortunately resulting in more frequent downtime toclean the furnace tubes.

Other approaches include injecting a silicone-based compound (e.g.polydimethylsiloxane compounds) to reduce foaming. These silicon-basedcompounds when used in excess have been known to poison downstreamhydrotreating catalysts. Catalyst poisoning is a severe problem as thecatalyst cannot be regenerated. Indeed, poisoned catalyst must bereplaced offline, which requires a costly shutdown of the hydrotreatingfacility as well as possibly other units in the refinery. The initialsilicon-based compounds are known to decompose and lose effectivenessover time, thus limiting their effectiveness and resulting in waste dueto the required constant addition of the compounds during key portionsof the coking cycle.

The problem of foaming in coke drums can be detected if appropriateindicators are available. By the time foaming is detected, however, itmay be too late to prevent undesirable carryover or plugging of overheadlines if action is not taken quickly.

SUMMARY

The present invention therefore, meets the above needs and overcomes oneor more of the deficiencies in the prior art by inhibiting orcontrolling foaming in hydrocarbon processes.

In one embodiment, the present invention includes a method for defoamingin a coking process comprising the steps of: i) providing a defoamingagent wherein the defoaming agent comprises a plurality of carbonnanoparticles; and ii) introducing the defoaming agent into the cokingprocess.

In another embodiment, the present invention includes a method fordefoaming in a coking process comprising the steps of: i) providing adefoaming agent wherein the defoaming agent comprises at least one of aplurality of carbon nanoparticles and a drag reducing agent; and ii)introducing the defoaming agent into the coking process.

Additional aspects, advantages and embodiments of the invention willbecome apparent to those skilled in the art from the followingdescription of the various embodiments and related drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention is described below with references to theaccompanying drawings in which like elements are referenced with likereference numerals, and in which:

FIG. 1 illustrates a coking process in accordance with the presentinvention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The subject matter of the present invention is described withspecificity, however, the description itself is not intended to limitthe scope of the invention. The subject matter thus, might also beembodied in other ways, to include different steps or combinations ofsteps similar to the ones described herein, in conjunction with otherpresent or future technologies. Moreover, although the term “step” maybe used herein to describe different elements of methods employed, theterm should not be interpreted as implying any particular order among orbetween various steps herein disclosed unless otherwise expresslylimited by the description to a particular order. While the presentinvention may be applied in the oil and gas industry with cokers, it isnot limited thereto and may also be applied in the oil and gas industrywith regard to oil and gas production where foaming is an issue, as wellas in other industries to achieve similar results.

Methods for defoaming in a hydrocarbon processes comprise the steps ofproviding a defoaming agent, and introducing the agent into ahydrocarbon process to inhibit or control foaming in the hydrocarbonprocess. The methods disclosed herein may be particularly useful asapplied to coking processes, especially as to foaming in coke drums. Forconvenience of reference, the term, “defoaming agent,” as used herein,refers to both defoaming agents and antifoaming agents, which eitherreduce existing foam or prevent foam initiation in the first place.

In certain embodiments, defoaming agents may comprise a plurality ofcarbon nanoparticles. In some embodiments, drag reducing agents maycomprise high-molecular weight alkanes. Other optional embodiments andfeatures are described in more detail below.

Advantages of methods of the present invention, include, but are notlimited to, more efficient and effective foam inhibition, reduced oreliminated product contamination, reduced or eliminated catalystpoisoning, increased refinery production rate, debottlenecking thecoker, and reduced cost and consequences of applying too much antifoam.

Reference will now be made in detail to embodiments of the invention,one or more examples of which are illustrated in the accompanyingdrawings. Each example is provided by way of explanation of theinvention, not as a limitation of the invention. It will be apparent tothose skilled in the art that various modifications and variations canbe made in the present invention without departing from the scope orspirit of the invention. For instance, features illustrated or describedas part of one embodiment can be used on another embodiment to yield astill further embodiment. Thus, it is intended that the presentinvention cover such modifications and variations that come within thescope of the invention. FIG. 1 illustrates one example of a flow diagramof a portion of a coking process in accordance with one embodiment ofthe present invention. Delayed coking process 100 generally comprisesfractionator 120, coker furnace 140, and coke drums 150A and 150B.Coking process 100 begins with refinery heavies 121 being fed tofractionator 120.

Light gases are removed overhead from fractionator 120 through overheadline 123. Heavier materials, such as gasoline, light gas oil, and heavygas oil are taken from fractionator 120 through lines 126, 127, and 128,respectively. LCGO or HCGO can be mixed with the feed stream 121 toreduce the viscosity of the mixture to permit easier handling andpumping of the mixture to the delayed coking part of the process. Thediluent heavy gas oil which is part of the gaseous effluent from thecoke drums does not substantially coke on its second pass through thecoker and therefore recycles through the system, keeping the viscositylower than it otherwise would have been.

All or some portion of the mixture of residual oil and heavy gas oilleaving fractionator 120 through line 125 is introduced to coker furnace140. Typically, this mixture of reduced crude oil and heavy gas oil isheated in coker furnace 140 to temperatures in the range of about 875°F. to about 975° F. at pressures of about atmospheric to about 250 psig.The heated mixture of reduced crude oil and heavy gas oil leaving cokerfurnace 140 and the total mixture is then passed via lines 151, 151A,and 151B as a feed to coke drums 150A or 150B. Coke drums 150A and 150Boperate on alternate coking and decoking cycles of from about 8 to about100 hours. While one drum is being filled with coke, the other drum isbeing decoked.

The overhead vapor from the coke drums is passed by lines 156A or 156Bto fractionator 120, wherein it is separated into various fractions aspreviously described. The green coke which is removed from the cokedrums through outlets 153A and 153B is further processed (not shown) toproduce calcined coke.

Although many variations of this coking process 100 are possible, thistype of operation is typical of a commercial unit. This illustration ismerely illustrative of coking processes and is not intended to belimiting.

As described above, a challenge frequently faced in coking processes isfoaming, particularly in one or more of the coke drums. In certainembodiments, a defoaming agent may be introduced into the cokingprocess, for example, by way of line 110A for combination with the cokefeed in first heated diluent line 151. Although the defoaming agent maybe introduced at any point upstream of coke drums 150A and 150B, anotherexample of an alternative injection point includes lines 110B forintroducing the defoaming agent into coke drums 150A and 150B. It couldalso be added upstream of coker furnace 140 at line 110C if it would notunduly degrade or cause substantial fouling in coker furnace 140.

In some embodiments, the defoaming agent comprises a plurality of carbonnanoparticles, but may be sub-micron particles. One advantage of usingcarbon nanoparticles is that any carbon nanoparticles remaining in thecoke product will not adversely affect the product. The carbonnanoparticles may range in any size effective to reduce foam in a cokingprocess and may be of any one or more of various shapes, includingnanofibers, single wall nanotubes, multi-wall nanotubes, regular-shapedparticles, irregular-shaped particles or graphene. Examples of suitablesize ranges of the carbon nanoparticles includes particles with adiameter of less than 100 nanometers. The amount of carbon nanoparticlesadded to the coking process may be from about 10 parts per million byweight (ppmw) to about 2000 ppmw of carbon nanoparticles relative tocoker feed.

The defoaming agent is thought to work by attacking the gas/liquidinterface and lowering the liquid surface tension.

The defoaming agent may be dissolved or dispersed in a carrier fluid tofacilitate transport of the defoaming agent as a liquid defoaming agent.Preferred carrier fluids comprise any fluid that is compatible with thecoking process and that does not adversely chemically interact with thedefoaming agent. Examples of suitable carrier fluids comprise kerosene,gasoline, light coker gas oil, heavy coker gas oil, light cycle oil, orany combination thereof. Alternatively, the carrier fluid may be ahydrocarbon having a boiling point less than about 1,000° F.

The defoaming agent, or liquid defoaming agent, may be introducedcontinuously, batchwise, or semi-batch into the coking process asdesired. In certain embodiments, the defoaming agent is introducedduring a last half of the fill cycle about an hour before foaming isexpected to reach a high level in the coke drum. If desired, foamdetection devices 157A, 157B may be installed in coke drums 150A and150B to detect foaming. In this way, detection of foam may indicate theneed for additional defoaming agent. Examples of foam detectinginstruments include, but are not limited to, level indicating devicessuch as nuclear level gauges using gamma radiation, radar gauges, or anyother non-intrusive level gauge that would not be subject to pluggingwith solid coke. In operation, an effective amount of carbonnanoparticles, the amount of carbon nanoparticles required tosubstantially inhibit foaming in the one or more coke drums, may then beintroduced into the coking process.

Where the defoaming agent comprises carbon nanoparticles, the carbonnanoparticles may be formed in the shape of platelets, shavings, fibers,flakes, ribbons, rods, strips, spheroids, hollow beads, toroids,pellets, tablets, or any combination thereof.

In certain embodiments, the defoaming agent is substantially free of anycomponent that adversely affects the coke product or that adverselyaffects any downstream refinery catalyst such as a hydrotreating orreforming catalyst. Examples of components which may adversely affectthe final coke product or downstream refinery catalysts include withoutlimitation silicone-based components such as polydimethylsiloxanecompounds and finely divided solids. Thus, the defoaming agent may befree of any silicone-based compounds. In other embodiments, however, thedefoaming agent may be combined with conventional silicon-basedcompounds such that the combination benefits from the use of both typesof components. Additionally, the defoaming agent may be selected to befree of any component capable of substantially changing the physicalproperties of any coke produced by the coking process or may be selectedto be free of any component capable of chemically interacting with ahydrotreater catalyst so as to poison the hydrotreater catalyst.

In certain embodiments, the defoaming agent may comprise a drag reducingagent, which serves as a flow improver. The drag reducing agent maycomprise any long linear alkane, including, but not limited to,substantially linear high-molecular weight poly alpha olefins or polymethacrylate with molecular weights ranging from about 1,000 to about2,000,000 atomic mass units (AMUs) and from about 1,000 to about10,000,000 AMUs.

In certain embodiments, the defoaming agent may comprise both aplurality of carbon nanoparticles and a drag reducing agent. Otheroptional components that may be included in the defoaming agent include,but are not limited to, kerosene, light coker gas oil, heavy coker gasoil, light cycle oil, diesel, vacuum gas oil, silicon antifoams, andother non-silicon antifoams.

While the present invention has been described in connection withpresently preferred embodiments, it will be understood by those skilledin the art that it is not intended to limit the invention to thoseembodiments. It is therefore, contemplated that various alternativeembodiments and modifications may be made to the disclosed embodimentswithout departing from the spirit and scope of the invention defined bythe appended claims and equivalents thereof.

What is claimed is:
 1. A method for defoaming in a coking processcomprising the steps of: providing a defoaming agent wherein thedefoaming agent comprises a plurality of carbon nanoparticles; andintroducing the defoaming agent into the coking process.
 2. The methodof claim 1 further comprising the steps of: providing a carrier fluidwithin which the defoaming agent is dissolved or dispersed to form aliquid defoaming agent; and introducing the liquid defoaming agent intothe coking process.
 3. The method of claim 2 wherein the carrier fluidcomprises at least one of kerosene, light coker gas oil, heavy coker gasoil, light cycle oil and gasoline.
 4. The method of claim 2 wherein thecarrier fluid is a hydrocarbon having a boiling point less than about1,000° F.
 5. The method of claim 1 wherein the defoaming agent isintroduced into a feed to one or more coke drums to control foaming inthe one or more coke drums.
 6. The method of claim 1 wherein thedefoaming agent is introduced into one or more coke drums to controlfoaming in the one or more coke drums.
 7. The method of claim 1 whereinthe amount of carbon nanoparticles is from about 10 parts per million byweight (ppmw) to 2000 ppmw of carbon nanoparticles relative to a cokerfeed.
 8. The method of claim 1 further comprising the steps of:detecting a presence of foaming in one or more coke drums using a levelindicator; and introducing an effective amount of the defoaming agentinto the coking process wherein the effective amount is determined ascomprising an amount of carbon nanoparticles required to substantiallyinhibit foaming in the one or more coke drums.
 9. The method of claim 1further comprising the step of continuously introducing the defoamingagent into the coking process.
 10. The method of claim 1 furthercomprising the step of continuously introducing the defoaming agent intothe coking process during a last half of a fill cycle of a coke drum.11. The method of claim 1 wherein the carbon nanoparticles are formed inthe shape of at least one of platelets, shavings, fibers, flakes,ribbons, rods, strips, spheroids, hollow beads, toroids, pellets andtablets.
 12. The method of claim 1 wherein the defoaming agent furthercomprises no silicone-based compounds.
 13. The method of claim 1 whereinthe defoaming agent further comprises no component capable ofsubstantially changing a physical property of any coke produced by thecoking process.
 14. The method of claim 1 wherein the defoaming agentfurther comprises no component capable of chemically interacting with ahydrotreater catalyst.
 15. The method of claim 1 further comprising thesteps of: continuously introducing the defoaming agent into the cokingprocess during a last half of a fill cycle of a coke drum; wherein thedefoaming agent further comprises no component capable of substantiallychanging the physical properties of any coke produced by the cokingprocess; and wherein the defoaming agent further comprises no componentcapable of chemically interacting with a hydrotreater catalyst.
 16. Amethod for defoaming in a coking process comprising the steps of:providing a defoaming agent wherein the defoaming agent comprises atleast one of a plurality of carbon nanoparticles and a drag reducingagent; and introducing the defoaming agent into the coking process. 17.The method of claim 16 wherein the defoaming agent comprises theplurality of carbon nanoparticles and the drag reducing agent.
 18. Themethod of claim 16 further comprising the steps of: providing a carrierfluid within which the defoaming agent is dissolved or dispersed to forma liquid defoaming agent; and introducing the liquid defoaming agentinto the coking process.
 19. The method of claim 18 wherein the carrierfluid comprises at least one of kerosene, light coker gas oil, heavycoker gas oil, light cycle oil, and gasoline.
 20. The method of claim 18wherein the carrier fluid is a hydrocarbon having a boiling point lessthan about 1,000° F.
 21. The method of claim 16 wherein the defoamingagent is introduced into a feed to one or more coke drums to controlfoaming in the one or more coke drums.
 22. The method of claim 16wherein the defoaming agent is introduced into one or more coke drums tocontrol foaming in the one or more coke drums.
 23. The method of claim16 wherein the amount of carbon nanoparticles is from about 10 parts permillion by weight (ppmw) to 2000 ppmw of carbon nanoparticles relativeto a coker feed.
 24. The method of claim 16 further comprising the stepsof: detecting a presence of foaming in one or more coke drums using alevel indicator; and introducing an effective amount of the defoamingagent into the coking process wherein the effective amount is determinedas comprising an amount of carbon nanoparticles required tosubstantially inhibit foaming in the one or more coke drums.
 25. Themethod of claim 16 further comprising the step of continuouslyintroducing the defoaming agent into the coking process.
 26. The methodof claim 16 further comprising the step of continuously introducing thedefoaming agent into the coking process during a last half of a fillcycle of a coke drum.
 27. The method of claim 16 wherein the carbonnanoparticles are formed in a shape of at least one of platelets,shavings, fibers, flakes, ribbons, rods, strips, spheroids, hollowbeads, toroids, pellets and tablets.
 28. The method of claim 16 whereinthe defoaming agent further comprises no silicone-based compounds. 29.The method of claim 16 wherein the defoaming agent further comprises nocomponent capable of substantially changing a physical property of anycoke produced by the coking process.
 30. The method of claim 16 whereinthe defoaming agent further comprises no component capable of chemicallyinteracting with a hydrotreater catalyst.
 31. The method of claim 16further comprising the steps of: continuously introducing the defoamingagent into the coking process during a last half of a fill cycle of acoke drum; wherein the defoaming agent further comprises no componentcapable of substantially changing a physical property of any cokeproduced by the coking process; and wherein the defoaming agent furthercomprises no component capable of chemically interacting with ahydrotreater catalyst.